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Liquid meters
Flow measurement begins with a properly operating flowmeter; however, measurement procedures and correct flow calculations equally contribute to good overall system performance.
Guidelines
Guidelines for liquid hydrocarbon measurement are detailed in the American Petroleum Institute’s (API’s) Manual of Petroleum Measurement Standards (MPMS), a comprehensive, ongoing publication in which chapters are periodically revised and then released. Commonly referenced standards include: Chap. 4 "Proving Systems," Chap. 5 "Metering," Chap. 7 "Temperature Determination," Chap. 9 "Density Determination," Chap. 11 "Physical Properties Data," Chap. 12 "Calculation of Petroleum Quantities," Chap. 13 "Statistical Aspects of Measuring and Sampling," Chap. 14 "Natural Gas Fluids Measurement," and Chap. 21 "Flow Measurement Using Electronic Metering Systems."
Characteristics
The information in this page covers the characteristics of three types of flowmeters that are commonly used for the measurement of liquid hydrocarbons:
- The selection criteria for a flowmeter
- The basics of field meter proving
- Specifics on the design and operation of a lease automated custody transfer (LACT) system
Classification
Liquid flowmeters can be classified in two general areas:
- A positive displacement meter that continuously divides the flowing stream into known volumetric segments, isolating the segments momentarily and returning it to the flowing stream while counting the number of displacements
- An inference meter that “infers” flow by measuring some dynamic property of the flowing stream
Typical inference meters are turbine meters that infer flow by monitoring impeller speed, orifice meters that monitor pressure differential, and the Coriolis meter, which senses the Coriolis force on vibrating tubes to infer flow rate.
Metering system design
Certain basic installation requirements are needed for proper operation of a positive displacement meter or a turbine meter. As a minimum, strainers, adequate upstream and downstream straight pipe, flow conditioning, and a downstream control valve are required. These meters operate best with clean fluid streams. Debris in the flow stream that is allowed to pass through the meter limits the life of the meter. A strainer or filter upstream of the meter should be utilized. A properly sized strainer that captures the destructive debris and keeps pressure drop to a minimum is a vital piece of equipment in a metering system.
Positive displacement and turbine meters are susceptible to disturbances in the flow stream. Flow disturbances can be caused by any upstream piping configuration that results in distortion of the fluid flow profile. Elbows and bends in the pipe upstream of the meter can produce a bulk swirl in the flowing fluid, which, if left uncorrected, could result in very unreliable measurements. For this reason, it is recommended that the meter be installed in a properly-sized run of pipe (or specially manufactured meter tube for greater accuracy) with a minimum of 10 diameters of straight unobstructed pipe upstream of the meter and 5 diameters downstream. It is important that all flanged connections in the upstream section to the turbine meter, as well as the downstream section, be properly aligned. Proper alignment throughout the metering section eliminates offsets, steps, and gaskets protruding into the bore, all of which can disturb the flow pattern. Dowel pinning of flanges can also aid in proper alignment of the metering section.
The historical method of flow conditioning utilizes straightening vanes or tube bundles. While this method is adequate for eliminating the swirl component of the flowing fluid, it does nothing for the velocity flow profile. Several manufacturers can provide isolation flow conditioners that eliminate the swirl and form a uniform velocity flow profile of the fluid before the flowmeter.
Proving connections downstream of the meter should be provided to facilitate proving of the meter, with a properly calibrated proving meter or “prover,” under conditions as close to the normal operating conditions as practical. See API MPMS Chap. 4 for further description of a prover. The proving connections consist of two tees separated by a block and bleed valve in the run of pipe downstream of the meter. Block valves are installed on the outlet of each tee to allow the prover to be attached and flow to be directed to it in series with the meter being “proved.”
Following the proving connections, another essential component for proper operation of the metering system is a control valve. The control valve is important because it helps to maintain a minimum backpressure on the meter to prevent meter cavitations and product flashing.
Unlike meters with moving parts, the Coriolis meter can handle typical pipeline solids without damage to the meter; however, a strainer upstream of the meter is recommended to protect the meter prover. No straightening vanes or flow conditioning is required for a Coriolis meter; therefore, no straight pipe sections upstream or downstream of the meter are necessary. This makes a Coriolis meter ideal for tight locations, as are typical on offshore platforms and for bidirectional metering systems. Consideration should be given to the location of the meter electronics that generate the pulse output so that the proving connections and the transmitter are located in close proximity.[1]
Valves to stop flow through the Coriolis meter are required. Verification that the meter registers zero flow in a nonflowing condition is required on initial installation. The zeroing procedure requires, as a minimum, a block and bleed valve downstream of the meter, and it is preferable to have a shutoff valve upstream to block the meter in during zeroing.
The Coriolis meter acts as a densitometer in addition to measuring flow. There is a considerable cost savings for metering systems that require both the measurement of flow and the measurement of density or gravity when the measurement can be made with a single instrument. Finally, the large turndown of a Coriolis meter can eliminate the use of a bank of several different size meters to cover the rates, again providing a cost savings for the metering system.[1]
Flowmeter performance
Manufacturers typically state performance characteristics for flowmeters based on a factory calibration utilizing water or other stable fluid. "Accuracy" is the measure of how close to true or actual flow the meter indication may be. It is expressed as a percent of true volume for a specific flow range.
Linearity
Linearity is defined as the deviation of measurement from the meter’s minimum flow rate specification to the maximum flow rate specification. It is generally expressed as a percentage. For example, a meter with a linearity statement of +/–0.25% means the meter factor for a given meter will not deviate more than 0.5% from the minimum to maximum flow rate.
Repeatability
Repeatability is the meter’s ability to indicate the same reading under the same flow conditions. For custody transfer applications, a meter’s repeatability is usually specified to be at least 0.05%.
Resolution
Resolution is another key parameter in a meter’s performance criteria. Resolution is a measure of the smallest increment of total flow that can be individually recognized by the meter.
Turndown
Turndown is the meter’s flow range capability. The flow range of the meter is the ratio of maximum flow to minimum flow over which the specified accuracy or linearity is maintained. For example, a meter with a minimum flow rate of 100 bbl/hr and a maximum flow of 1,000 bbl/hr is said to have a 10:1 turndown. For positive-displacement meters, excessively low rates tend to under-register flow as slippage increases. At excessively high flow rates, there is an increase in wear. A meter should operate optimally around the midpoint of its rated flow range.
Flowmeter selection
Fluid properties often dictate proper meter selection in a liquid application. Liquids such as anhydrous ammonia, refined hydrocarbons like gasoline or diesel, crude oil, and liquefied petroleum gas (LPG) have differing fluid properties such as density, viscosity, pour point, flash point, flowing temperature, and flowing pressure. All of these factors are important when specifying the requirements for the flowmeter. Fig. 1 is a flowmeter application guide based on fluid properties.
Fig. 1—Flowmeter application guide (Courtesy of the Emerson Process Management).
Pressure drop through a meter is the amount of permanent pressure loss that is a result of the liquid passing through the meter. Meter manufacturers can provide data to compute expected pressure drop for a variety of liquids. As the viscosity and/or flow rate of the measured product increases, so does the amount of pressure drop. The specified design pressure of the system and the minimum and maximum operating pressures should be provided to the manufacturer. The maximum pressure is used to ensure that the mechanical rating of the meter is sufficient. The minimum pressure is needed to ensure that adequate pressure is available in the system to allow for pressure drop through the meter while maintaining the fluid in a liquid state—in other words, to prevent the product from flashing or changing to a gaseous state. Control valves or backpressure valves are often recommended to maintain sufficient pressure on the fluid as it is metered.
Fluid temperature and ambient temperature are factors to consider. If the product is very cold or very hot, it could well exceed the manufacturer’s temperature limits for the electronics, as well as exceed the standard materials temperature range for the meter body or internal parts.
Flowmeters that have internal moving parts may be affected by changes in liquid density and viscosity. For light hydrocarbons, the minimum flow rate capability of the meter may need to be increased to maintain specified linearity and repeatability. Viscosity can also affect the low end of the meter’s flow range. The actual viscosity of the fluid at operating or flowing temperature is what is relevant. A crude oil may have a viscosity of 50 cSt at 60°F; however, the temperature of the crude at flowing conditions may be 80°F, which would significantly reduce the viscosity and increase the actual flow rate range of a given meter.
Chemical compatibility must be considered in the material selection of all internal wetted surfaces. Dry, abrasive products may require special lubricating systems that isolate bearings and gears from the product. Entrained solids are not readily passed by most flowmeters and should be removed by an appropriately meshed strainer upstream of the meter.
Most meters yield gross measurement inaccuracies with a product that contains either free or entrained air. Removal of this air with an appropriately sized air eliminator is essential. Large volumes of free air not only impair accuracy but can also overspeed and destroy a meter with moving parts.
As with all metering systems, the choice of flowmeter technology should be based on cost of ownership. Cost of one type of meter relative to another varies by size and manufacturer. The initial cost, however, is only one of several costs that should be considered. For example:
- Accuracy: consider a 16-in. pipeline meter flowing at 12,000 bbl/hr. With oil priced at $22/bbl, an improved accuracy of only .05% could result in a savings of U.S. $132 for every hour of operation.
- Maintenance: recurring costs in maintaining a meter can be a significant factor in overall meter cost.
Flow calculations and overall system performance
Most flowmeters output a pulse that represents gross volume (volume at flowing conditions). Gross volume is then converted to net volume (volume at contract conditions) with the appropriate corrections for:
- Temperature
- Pressure
- Sediment and water (S&W)
- Meter factor
With custody transfer, line integrity, or allocation based on net volumes, it is critical to accurately measure all variables and to maintain all measurement equipment.
PLCs, SCADA equipment, and flow computers offer a huge benefit for real-time monitoring of measurement stations. They offer the advantage of being able to act in a timely manner upon information that can save thousands of dollars in revenue.
References
- ↑ 1.0 1.1 Yon, Marsha. 2009. Coriolis meters for liquid measurement. Micro Motion, Inc. http://library.ceesi.com/docs_library/events/ishm2009/Docs/2260.pdf. (PDF)
Noteworthy papers in OnePetro
Lichen, Z., Jiaqing, Y., Xiaohan, P., He, L., & Zhengyun, Z. 2015. Swing-Rod Flowmeter - A New Downhole Flow Measurement Technology. Society of Petroleum Engineers. http://dx.doi.org/10.2118/176399-MS.
Amin, A. 2015. Evaluation of Commercially Available Virtual Flow Meters (VFMs). Offshore Technology Conference. https://www.onepetro.org/presentation/OTC-25764-PT. (Video)
External links
See also
Positive displacement liquid meters
Liquid flow meter proving and LACT units
PEH:Liquid_and_Gas_Measurement